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20 August 2020
Project EnergyConnect Update
Stakeholder Webinar
2
Webinar Outline
Agenda item Lead Organisation Time
1. Welcome and context Rainer Korte ElectraNet 10 min
2. Project EnergyConnect in the
2020 Integrated System Plan
Craig Price AEMO 10 min
3. Updated cost benefit analysis Brad Harrison ElectraNet 20 min
4. Developing capital expenditure
forecasts
Chris Swann
Ralf Ricciardi
TransGrid
ElectraNet
10 min
5. Q&A Rainer Korte ElectraNet 30 min
6. Conclusion and next steps Rainer Korte ElectraNet 10 min
Rainer Korte
Group Executive Asset Management
ElectraNet
Context
4
▪ Changes to PEC costs and benefits
▪ Why PEC is included in each of the AEMO
Final 2020 Integrated System Plan (ISP)
future scenarios and development paths
▪ Draft results of updated cost benefit
analysis aligned to the 2020 ISP
▪ Additional risks and benefits addressed by
PEC
▪ What we are doing to drive the lowest
project delivery cost for customers
What you will hear about today
Project EnergyConnect (PEC) is a new high capacity
electricity interconnector between SA and NSW
5
▪ PEC is a central part of AEMO’s roadmap in the
ISP for the transition of the power system and is
expected to deliver benefits across the NEM – this
is reinforced by the RIT-T modelling
▪ For NSW customers, the interconnector improves
diversity of supply and access to cheaper
renewable energy sources as the coal fleet
progressively retires – it also unlocks significant
renewable energy development along the route
▪ For SA customers, the interconnector provides
access to additional capacity when needed to
replace expensive gas generation and improves
the resilience and security of the power system
▪ Previous price impact modelling indicated price
reductions are expected in both regions which
outweigh the additional transmission costs to
customers by a factor of 6 – 7 times or more
Benefits of Project EnergyConnect
6
Background: Project economic assessment (the RIT-T)
Nov 2016
RIT-T Project Specification Consultation
Report (PSCR)
published
Q1 2017
Stakeholder consultation
and submissions
Extensive market
modelling and
economic assessment undertaken
Jun 2018
RIT-T Project Assessment Draft Report
(PADR) published
Q3 2018
Stakeholder consultation
and submissions
Q4 2018
Revised economic
assessment undertaken
Feb 2019
RIT-T Project Assessment Conclusion
Report (PACR)
published
The RIT-T* considered options to reduce the cost of secure and reliable
electricity while facilitating NEM-wide transition to renewable energy
Customer and Stakeholder Engagement
* The Regulatory Investment Test for Transmission (RIT-T) is the economic cost benefit
test overseen by the Australian Energy Regulatory (AER) and applies to all major
network investments in the National Electricity Market (NEM)
7
Background: Post RIT-T economic assessment
Apr 2019
ElectraNet requests RIT-T determination
under NER 5.16.6
May-Dec 2019
AER conducts detailed review of
RIT-T analysis
Jan 2020
AER makes NER 5.16.6
determination approving the
RIT-T
Mar to Aug 2020
ElectraNet undertakes
updated cost benefit
analysis*
Jul to Aug 2020
ElectraNet variable heat
rates consultation
30 Jul 2020
AEMO releases Final
2020 Integrated
System Plan
Aug 2020
AER begins review of
updated cost benefit
analysis
In January 2020, the AER approved the RIT-T noting that “any significant
changes to the costs of the preferred option could have a material impact on the
outcome of the RIT-T”
Customer and Stakeholder Engagement
* The purpose of the updated cost benefit analysis is to investigate whether there has
been a “material change of circumstances”, considering new information on both
costs and benefits aligned with AEMO’s Final 2020 ISP
8
Variable heat rates stakeholder consultation
What we heard How we are responding
General acceptance of variable heat rates, with some
minor refinements and caution over ‘finessing’
We will apply variable heat rates as a more accurate
representation of generator operating costs
Concerns over the economic case for the project
given the changes in costs and benefits
We are undertaking an updated cost benefit analysis to examine
whether a “material change in circumstances” has occurred, to
be published and submitted to the AER for confirmation
Concern over the imbalance of benefits and costs
between NSW and SA
AEMO’s 2020 ISP shows NEM-wide benefits. TransGrid is also
securing updated information on NSW benefits.
EnergyQuest gas forecast advice should be released We have applied the AEMO 2020 ISP gas price forecasts but will
publish a summary of the EnergyQuest report
Analysis underlying AEMO’s 2-unit synchronous
generator requirement should be published
Further information on the 2-unit requirement was released in
the 2020 ISP, and a separate report has been published by
AEMO with the latest information on SA system security risks
Proposed route through Dinawan does not address
Darlington Point constraints
A separate RIT-T has been initiated by TransGrid to address the
Darlington Point constraints – there is no material impact from
the Dinawan route refinement on the current RIT-T
Craig Price
Group Manager System Planning
AEMO
Project EnergyConnect and the 2020
Integrated System Plan
2020 ISPOutlineAugust 2020
Power station closures
11
Across the NEM –Coal is replaced by VRE and DER...supported by firming resources (mostly storage, GPG operation)
12
Generation mix, Optimal development path, Central scenario
0
20,000
40,000
60,000
80,000
100,000
120,000
Inst
alle
d C
ap
aci
ty (M
W)
Black Coal Brown Coal CCGT Peaking Gas+Liquids
Hydro Large-scale Battery Pumped Hydro Total Behind the Meter Battery
Wind Solar DSP Distributed PV
Dispatchable Capacity
The optimal development path (ODP) under Central scenario
13
33 GW* of additional VRE
(solar and wind) generation
required by 2040
VNI minor by 2022-23#
12 GW of additional DER
(mainly distributed PV)
required by 2040
Project EnergyConnectby 2024-25 #
13 GW of new dispatchable
capacity (mainly storage) required
by 2040
HumeLink by 2025-26#
Future ISP projects with preparatory
activities by 30 June 2021
Committed generation and transmission to
proceed as planned
Central-West Orana REZ
Transmission Link by 2024-25
#
*Regional VRE split:
• 11 GW QLD
• 12 GW NSW
• 6 GW VIC
• 3 GW SA
• 1 GW TAS
Actionable
ISP projectsFuture ISP projectsDevelopment opportunities
VNI West by 2027-28 with
decision rules
Marinus Link by no later than 2031-32 with
decision rules
Future ISP projects no
action before next ISP
# Estimated practical
completion including any
subsequent testing, project is
optimal if can be delivered
earlier
Optimal development path
14
2030s Far North QLD REZ
2030s Gladstone Grid Reinforcement
Early-2030s Central to Southern QLD
Mid-2020s Central-West Orana REZ
Transmission Link
2030s New England REZ
2026-27 to
2032-33 Reinforcing Sydney,
Newcastle & Wollongong Supply
2030s QNI Medium & Large
2021-22 Minor QNI Upgrade
2024-25 Project EnergyConnect
2025-26 HumeLink
2022-23 VNI Minor
2028-29 to 2031-32
Marinus Link Stage ”
2030s Mid-North REZ
2030s South-East REZ
SVC
2025-26 Western Victoria
Transmission Network Project Existing network
Network upgrade
Alternative network routes
Indicative wind farm
Indicative solar farm
Indicative deep storage
Indicative shallow storage
System strength remediation
Capacitor
Static VAr Compensator
Decision rules may affect timing
SVC
Brisbane
Sydney
Hobart
Bundaberg
Rockhampton
Mackay
Proserpine
Forsayth
Cairns
Armidale
Dubbo
Newcastle
Wollongong
Broken Hill
Coober Pedy
Ceduna
Be ndigo
Launceston
Queenstown
Canberra
2021-22 System Strength
Longreach
1
2
3
MelbourneBallarat
AdelaidePort Lincoln
Mount Gambier
Gladstone
Townsville
SVC
2031-32 to 2035-36
Marinus Link Stage 2”
2027-28
VNI West
Emerging system security risks
• AEMO report “Minimum Operational Demand Thresholds in
South Australia” (April 2020) identifies new emerging system
security risks due to continuing growth in distributed PV and
falling minimum demand levels
• Security risks are forecast to keep growing year on year until
solutions are implemented
• AEMO report recommends Project EnergyConnect proceed as
an “essential foundational measure” to address these risks
• The project would reduce the likelihood of SA “islanding” from
the NEM and alleviate the most challenging of the system
security issues identified by AEMO
15
Brad Harrison
Power System Planning Manager
ElectraNet
Updated Cost Benefit Analysis
(CBA)
17
Contents
▪ AER RIT-T Determination
▪ Updates since the RIT-T Determination
▪ SA system security risks
▪ Indicative results
▪ Additional considerations
18
AER RIT-T Determination
▪ The AER approved the RIT-T, finding the business case to
be “robust”
▪ The AER determined that the proposed interconnector
remained the most “credible option that maximises the net
economic benefit”
▪ It also noted that any significant change to the cost of the
preferred option could have a material impact on the RIT-T
outcome
▪ Our updated cost benefit analysis examines whether
changes to inputs and assumptions aligned with the 2020
ISP would change the RIT-T outcome, using the same
methodology reviewed and approved by the AER
19
Updates since the RIT-T Determination
Key Changes Description Source
Variable heat rates for
thermal plant
Variable heat rates applied (in place of minimum capacity factors) to more
accurately model generator fuel costs2020 ISP data
Gas prices
Gas price forecasts have increased ($12/GJ long-term), aligned to 2020 ISP
central scenario assumptions and supported by independent advice from
EnergyQuest
2020 ISP data
Energy storage costsPumped hydro storage costs have increased, while battery storage costs are
42% higher initially, but decline more rapidly to 20302020 ISP data
Committed generation
projects
Committed generation projects throughout the NEM have been updated in
line with the 2020 ISP2020 ISP data
Generator retirementsPlant retirements have been updated based on dates announced under the
Rules2020 ISP data
New system security
requirements in SA
New constraints have been modelled to manage increasing risks from
distributed PV and new frequency response requirements to manage the risk
of ‘islanding’
2020 ISP
(Appendix 7)
Actionable ISP projectsUpdated to include the actionable ISP projects in the 2020 Final ISP including
the accelerated timing of the VNI West project2020 ISP
20
System security risks
▪ Network constraints are modelled as recommended by
AEMO in the 2020 ISP and its report to the SA
Government to:
‒ Ensure sufficient headroom on Heywood Interconnector
for a credible contingency event
‒ Manage the risk of separation where the loss of
Heywood is high risk and high consequence
‒ Allow for stable “islanded” operation through additional
frequency response requirements
21
Draft modelling results – SA Gas Generation
In the base case:
▪ Updated modelling shows higher gas
usage than the AER sensitivity
▪ Benefits are calculated on much
lower gas usage than has been
observed historically, which is a
conservative outcome
▪ Unused gas is available for
alternative uses in the eastern states
0
10
20
30
40
50
60
70
Ga
s in
pu
t (P
J)
Fiscal Year
Actual PACR AER Sensitivity 1 Updated CBA
22
Draft modelling results compared to ISP – NEM investment
▪ Similar generation and storage
investment profile across the
NEM
▪ NEM wide outcomes of updated
modelling are well aligned with
ISP outcomes
0
20,000
40,000
60,000
80,000
100,000
120,000
Insta
lled c
apacity (
MW
)
Updated CBA AEMO 2020 ISP Central
23
Draft modelling results compared to ISP – NEM Emissions
▪ Similar emissions profile in
base case results
▪ NEM wide outcomes of
updated modelling are well
aligned with ISP outcomes
0
20
40
60
80
100
120
140
160
Em
issio
ns C
O2
e (
ton
ne
s)
Updated CBA AEMO 2020 ISP Central
24
Draft updated gross benefits
Central scenario benefits have
increased with updated inputs
0
500
1,000
1,500
2,000
AER Sensitivity 1 Updated CBA
Gro
ss b
enefits
($m
2018
-19)
Avoided variable cost
Avoided fixed costs
Avoided capital costs
Avoided transmission capital costs
25
Scenario weighted benefits
▪ Our updated CBA is based on the
AEMO Central – accelerated VNI
West development path
▪ Weighted benefits can be expected
to be higher than central scenario
▪ AEMO’s 2020 ISP demonstrates
large increased benefits of
transmission if the world moves
quickly towards a renewable future
▪ Therefore PEC is considered to be a
very low regret investment
$7,298$7,688 $40,559 $14,051
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
AEMO Central -accelerated VNI
AEMO Central - least cost AEMO Step Change -accelerated VNI
AEMO Fast Change -accelerated VNI
Net
mark
et benefits
($m
, 2018
-19)
Weighted benefit across all scenarios
26
Power system resilience
▪ Recent events demonstrate the need for additional and diverse interconnection to
reduce the risk of islanded operation
▪ AEMO’s minimum operational demand thresholds review states “Completion of the
interconnector … should be considered crucial for the ongoing security of South
Australia’s power system”
▪ Improved resilience is built into the design and operation of the new interconnector
▪ The benefits of this improved system resilience have not been quantified in the CBA
27
Indicative results of updated cost benefit analysis
▪ Market benefits are being finalised
in line with 2020 ISP
▪ Capex forecasts to be finalised in
September 2020
▪ Indicative net benefits are in range
$100m to $400m
▪ A weighted scenario approach
would result in higher net benefits
▪ And system resilience benefits
remain unquantified
▪ Again PEC is considered to be a
very low regret investment
$0
$100
$200
$300
$400
$500
$600
$700
$800
1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800
Ne
t m
ark
et b
en
efit ($
m 2
01
8-1
9)
Cost real ($m 2018-19)
Ralf Ricciardi
Project Director
ElectraNet
Developing capital expenditure
forecasts
Chris Swann
Major Projects Director
TransGrid
29
ElectraNet procurement process
Market Engagement
EOI to assess
contractor capability
and capacity
RFP to further refine
market pricing
RFT for Design &
Construction (D&C)
contract(s)
Execution of Design &
Construction contracts
❑ Strategy
‒ Minimise risk related to:
▪ Safety
▪ Weather delays
▪ Latent conditions
▪ Environmental and Cultural
Heritage issues
▪ Technical/ Design
‒ Early contractor involvement to
reduce risk
‒ Correctly allocate and price risks
‒ Effective coordination of project
delivery with TransGrid
❑ Majority of project costs will be
covered by competitive market
pricing (~ 75%)
Now
30
TransGrid procurement process
5x EOIs
Q4 2019
3x Binding Bids
29 June 2020
2x BAFOs
1 Sept 2020
Commitment Deed
30 Sept 2020
FID & EPC Deed
15 Dec 2020 (Target)
❑ Strategy
‒ Turnkey D&C solution
‒ Output-based specification
‒ Demonstrate value through
competitive process
‒ Three binding bids from
CPB/UGL, Elecnor/Clough and
Quanta
‒ Residual risks relate to
planning approvals, Covid-19
and extreme weather events
❑ ~75% of the project costs are
covered by the procurement
process
‒ Remainder of budget covers
property, biodiversity & “thin
client” delivery
31
▪ PEC has a very different risk and cost structure to BAU projects
▪ Price discovery has been an important part of the development process
Drivers for project outturn costs
Value drivers Cost drivers
Competitive tension Technical standards
Pipeline of ISP projects WH&S
New contractors & suppliers Biodiversity & property impacts
Output-based specification Congested infrastructure market
Scale economies Specialist labour requirements
Rainer Korte
Group Executive Asset Management
ElectraNet
Q & A
Rainer Korte
Group Executive Asset Management
ElectraNet
Conclusion and next steps
34
▪ While there have been significant changes in both costs and benefits, the preferred option
remains unchanged and there has been no “material change in circumstances”
▪ This draft conclusion is based on updated market benefits modelling aligned with the 2020 ISP
and updated project cost estimates to be confirmed in September 2020
▪ Additional unquantified benefits are also expected through improved system resilience
▪ The ISP includes PEC in all future scenarios and potential development paths for the NEM,
including the optimal development path which is designed to deliver the greatest potential
customer benefits and lowest costs over time
▪ AEMO has separately recommended PEC as as an “essential foundational measure” to
address emerging system security risks that are growing year on year
▪ PEC is a very low regret investment essential to our energy future
Conclusion
35
▪ Conclude and publish the updated
cost benefit analysis
▪ AER to review and confirm the
outcomes of the updated analysis
▪ TransGrid and ElectraNet to finalise
project cost forecasts and submit
Contingent Project Applications to
the AER (subject to AER
acceptance of the updated CBA)
▪ AER to review, consult and make
contingent project determinations
Immediate next steps
Project EnergyConnect
For additional information go to www.projectenergyconnect.com.au
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